1. Field of the Invention
The present invention generally relates to rigs for deploying bottom hole assemblies (xe2x80x9cBHAsxe2x80x9d) that are connected to a flexible umbilical. More particularly, the present invention relates to transportable rigs for deploying multi-segment BHAs connected to composite coiled tubing. In another aspect, the present invention relates to methods for deploying BHAs connected to flexible umbilicals. In still another aspect, the present invention relates to methods of automating the deployment of BHAs connected to a flexible umbilical.
2. Description of the Related Art
Many existing wells include hydrocarbon pay zones that were bypassed during original drilling and completion operations. Well operators or owners chose not to complete these zones because these bypassed zones were not economical to complete and produce. That is, the expected recovery rate of hydrocarbons from a bypassed zone did not justify the cost of implementing the downhole equipment need to complete and produce the bypassed zone. For example, offshore drilling platforms can cost upwards of $40 million to build and may cost as much as $250,000 a day to lease. Such costs preclude the use of such expensive platforms to exploit hydrocarbon pay zones that may not produce hydrocarbons in sufficient quantity or rates to offset these costs. Thus, often only the larger oil and gas producing zones are completed and produced because those wells are sufficiently productive to justify the cost of drilling and completion using conventional offshore platforms. Similar economic considerations also come into play for land based wells. Because many major oil and gas fields are now paying out, there is need for a cost-effective method of producing these previously bypassed hydrocarbon pay zones.
Cost effective production of bypassed zones requires, in part, drilling and completion systems and methods that can efficiently reach these subterranean formations. Also required are surface support and control systems that can economically deploy these drilling and completion systems and methods.
The system and methods disclosed in commonly-owned U.S. application Ser. No. 09/081,961, entitled xe2x80x9cWell System,xe2x80x9d filed on May 20, 1998, now U.S. Pat. No. 6,296,066, which is hereby incorporated herein by reference for all purposes, addressed the first need. One embodiment of a system disclosed in the xe2x80x9cWell Systemxe2x80x9d application for economically drilling and completing the bypassed pay zones in existing wells includes a bottom hole assembly disposed on a composite umbilical (hereinafter a xe2x80x9cCCT BHAxe2x80x9d) made up of a tubing having a portion thereof which is preferably non-metallic.
Referring to FIG. 1, there is shown a BHA 10 disposed in a lateral borehole 12 branching from a primary wellbore 14. BHA 10 is operatively connected to a composite coiled tubing umbilical 16 and may include a drill bit and other modules or segments. BHA segments may include a gamma ray and inclinometer and azimuth instrument package, a propulsion system with steerable assembly, an electronics section, a resistivity tool, a transmission, and a power section for rotating the bit.
Because composite tubulars are much lighter and more flexible than steel pipe and steel coiled tubing, the operational reach of a drill or working string formed of composite coiled tubing 16 is significantly increased for at least two reasons. One reason is that the relative lightweight nature of composite coiled tubing lessens the power required of downhole tractors and other transport systems.
A closely related second reason is that composite tubing can be designed to be neutrally buoyant in drilling mud. In an ordinary case, high pressure drilling mud is pumped from the surface to the BHA 10 via the composite umbilical 16. The hydraulic pressure of the drilling mud is used to power the propulsion system and to rotate the drill bit. The drilling mud exits the BHA 10 through nozzles located on the drill bit. The exiting drilling mud cools the drill bit and flushes away the cuttings of earth and rock. Drilling mud returns to the surface via the annulus 19 defined by the wall 21 of lateral wellbore 12 and composite coiled tubing 16. The materials for composite tubing 16 and the drilling mud can be selected to achieve neutral buoyancy in the drilling mud in which the composite coiled tubing is immersed. Thus, downhole tools, such as propulsion systems, need only provide sufficient force to tow neutrally buoyant composite coiled tubing 16 through wellbore 12 and to plan a force on the drill bit.
The profitability of bypassed zones also depends, in part, on the costs associated with introducing, operating, and retrieving a drilling and completion system, such as a CCT BHA, at a given well site. Prior art drilling rigs have inherent drawbacks that reduce the cost effectiveness of using drilling and completion systems to construct new wells and workover existing wells. Some of these drawbacks are discussed below.
The prior art does not disclose rigs that may be readily moved from one well to another on a well site. For example, as is well known in the art, subterranean hydrocarbon fluids are typically under significant pressure. During drilling, this pressure must be controlled to prevent hydrocarbon fluids from surging up the wellbore and causing a xe2x80x9cblow-outxe2x80x9d at the surface. Blowout preventers are attached to the wellhead to control this well pressure. In order to contain this well pressure, it is important that the BOP""s and related components making up the BOP stack be tightly sealed. Before a prior art drilling rig supporting a CCT BHA system can be moved from a first well to a second well at a given well site, the valves and other joints making up the BOP stack must be disassembled. These valves and joints must be reconnected and tested after the rig has been moved above the second well. Considerable time and effort may be saved if this disassembly procedure could be minimized. Thus, what is needed is a rig that provides for the movement of a BOP stack as an integral unit to minimize the time and costs associated with servicing multiple wells at a given well site.
The prior art also does not disclose rigs that are readily moved between well sites to support drilling and completion operations. Prior art rigs are generally not designed to be connected and disconnected at several successive well sites. Thus, well construction or well workover often require a new rig to be constructed at each well site. What is needed is a rig that can be constructed at a given well site and then disassembled and moved to a second well site for re-use. Such a rig would minimize the need for additional rig superstructures.
The prior art also does not disclose a rig that effectively supports the introduction of a CCT BHA into a well. A CCT BHA designed in accordance with the above description may be over fifty feet in length. Because handling such a long BHA can be unwieldy, the many components making up the BHA are usually assembled into multiple BHA modules or segments. These BHA segments are in turn connected together to form a complete BHA. Such a procedure using prior art rigs is cumbersome because prior art rig do not provide means to mechanically manipulate and dispose successive BHA segments into a well. Thus, what is needed is a rig that facilitates the deployment of BHA segments into a well.
As can be seen, prior art rigs are not cost effective with respect to service multiple wells. Moreover, prior art rigs limit the economical use of CCT BHAs in servicing bypassed wells and also increase the cost of constructing new wells.
The present invention overcomes the deficiencies of the prior art.
The preferred embodiment of the present invention includes a modular rig fitted with a stabilizer for lifting/lowering an injector and BOP stack and a powered arm adapted to manipulate the BHA segments. The rig includes a tower made up of a plurality of interlocking modules. The tower is mounted on two perpendicularly aligned skids. In an exemplary deployment, the rig is initially assembled at a first well site with the skids preferably disposed such that the tower can be moved over at least two wells. After a first well is serviced, the tower is moved on the skids over to the second well. Once all wells at the first well site are serviced, the rig is disassembled into individual rig modules and moved to a second well site. Thus, an advantage of the present invention is that one rig may be deployed in several successive operations thereby minimizing the costs of constructing multiple rigs.
The preferred rig includes one module that is provided with an equipment skid to support the stabilizer. The stabilizer supports the injector and BOP stack. The stabilizer includes hydraulic lifts that can raise the injector and BOP stack off the wellhead. Thus, before the rig is moved on the skids from one well to another at a well site, the connection between the BOP stack and wellhead is disconnected. Thereafter, the stabilizer is actuated to lift the injector and BOP stack and the entire assembly is moved as one piece. The stabilizer also preferably accommodates the thermal expansion of the BOP stack by rising and lowering the work string and BHA during well servicing operations. Thus, an advantage of the present invention is that assembly time and costs for moving a BOP stack is minimized.
The powered arm is attached to the rig tower and includes an articulated gripper for manipulating the CCT BHA segments. Preferably, the powered arm is controlled by a general purpose computer that guides the powered arm through a predetermined sweep that begins with grasping a CCT BHA segment and ends with positioning the CCT BHA segment above the injector. Thus, an advantage of the present invention is that manual lifting and handling of CCT BHA segments is minimized.
Thus, the present invention comprises a combination of features and advantages which enable it to overcome various problems of prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon studying the following detailed description of the preferred embodiments of the invention, and by referring to the accompanying drawings.